MX2013012731A

MX2013012731A - Method and apparatus for the downhole injection of superheated steam.

Info

Publication number: MX2013012731A
Application number: MX2013012731A
Authority: MX
Inventors: Jimmy L Turner; Richard B Graibus; Charles T Mccullough; Dennis K Williams
Original assignee: Trimeteor Oil And Gas Corp
Priority date: 2012-11-02
Filing date: 2013-10-31
Publication date: 2014-10-13
Also published as: MX340845B; US9353611B2; US20140124203A1

Abstract

Superheated steam from a generator (10) proximate a well (14) is delivered through an output pipe (12) that communicates through a dual entry wellhead (17) with downhole steam piping (18) extending into the well (14). Steam is delivered at approximately 50 PSIG over the frictional and other losses encountered from the surface to the steam piping outlet (19). Oil is extracted through production tubing (20) passing through wellhead (17). Production tubing (20) and steam delivery piping (18) are secured in parallel relationship by clamps (46). The production tubing (20) communicates with a lift pump, and the steam piping (18) is terminated generally at a midpoint of the production tubing (20), several feet above the lift pump. A thermocouple (43) is placed approximately two feet below the end of the steam piping (18).

Description

METHOD AND APPARATUS FOR INJECTING OVERHEATED VAPOR IN THE ONE WELL BACKGROUND FIELD OF THE INVENTION The present invention relates generally to the injection of superheated steam at the bottom of a well to recover crude oil of low specific gravity, to improve reservoir control, and for deparaffinization. More particularly, the invention relates to improved oil recovery methods and apparatus for injecting superheated steam underground with a consistent heat capacity of 482.22 ° C (900 ° F), ie, steam with a minimum temperature of 482.22. ° C (900 ° F) above the saturation temperature of a water / steam mixture, at a pressure sufficient to overcome the frictional pressure losses associated with the roughness of the surface of the downhole pipe, the velocity of the steam mass flow, the geometrical parameters within the bottom of the well that exist from the upper lateral surface to the outlet of the steam pipe at the bottom of the well, concurrently with the normal oil extraction processes that work through Separate production pipes.

BACKGROUND OF THE INVENTION It has long been recognized in the art that when the natural impulse energy in a reservoir or oil well diminishes over time, it becomes increasingly difficult to lift oil to the surface. When the pressure decreases with time, secondary and tertiary methods are used to carry oil to the well where it can be recovered. Artificial elevation in the well will be required to achieve sufficient production. Several artificial lift processes are commonly used to increase reservoir pressure and force oil to the surface at some point during the life of a well.

The two most common methods for inducing artificial lift in wells are widely referred to as "pumping" and "gas injection". The equipment is coupled to the pump by rocker above and below the ground to increase the pressure and push the oil to the surface. Rocker pumps, consisting of a string of suction rods and a suction rod pump, are exemplified by the common black rod pumps used by oil wells on land that create suction to lift the oil .

Above the surface, the rocker pumping system swings back and forth, making reciprocate a string of suction rods, which penetrate down the bottom of the well. The suction rods are connected to the suction rod pump, which is installed as part of the pipe string near the bottom of the well. The rocker pump system swings back and forth to operate the rod string, the suction rod and the suction rod pump. The suction rod pump elevates the oil from the reservoir through the well to the surface. Pumping by artificial lift can also be done with a hydraulic pump at the bottom of the well, instead of suction rods, or with electric submersible pump systems deployed at the bottom of the pipe string. An electric cable runs along the depth of the well.

Artificial lift systems can employ gas injection to re-establish pressure, causing a well to produce. The gases or vapors injected reduce the pressure at the bottom of the well, decreasing the viscosity of the fluids in the well. This, in turn, encourages fluids to flow more easily to the surface. Typically, the gas that is injected is recycled with fluids produced from the well.

Gas lift is the optimal choice for offshore applications. Running at the bottom of the well, the compressed gas is injected down through the Liner pipe ring, entering the well at numerous entry points called lift valves. When the gas enters the pipe at these different stages, it forms bubbles, lightens the fluids and / or lowers the pressure.

It is well known in the art to inject high temperature steam into wells to decrease the viscosity of heavy crude oils, facilitating subsequent pumping and recovery. The temperature of the injected steam must be at or above the saturation temperature at a given injection pressure. The injected steam heats the well, heating the pipe, the linings and the surrounding environment. The injected steam should not only be at sufficient temperature and pressure to properly liquefy the target crude oil in the well, but a sufficient volume of that steam is required during the injection process for success. In general, in the prior art, large volume demands are mitigated by counting the maintenance of a successful operation of the required applied steam temperature.

Steam generators for supplying superheated steam are known in the art. For example, U.S. Patent No. 4,408,116 issued to Turner on October 4, 1983 describes a superheated steam generator with two heating stages. A design of More recent steam generator is illustrated in our earlier US Patent No. 8,359,919 issued on January 22, 2013 and entitled "Superheated Steam Generator with Heating Tanks Accommodating Slack", which is owned by the same transferee as in this case .

Currently there are several different forms of steam injection technology for oil recovery. The two main methods of the prior art are "Cyclic Steam Stimulation" and "Steam Inundation". The "Cyclic Steam Stimulation" method, also known as the "Blow and Blow" method, consists of the injection, soaking, and production stages. The steam is first injected to heat the oil in the reservoir to raise the temperature and lower the viscosity of the oil, thereby improving fluid flow. The injected steam can be left in the well for periods of time to soak and diffuse the steam into the well's environment. Subsequently, the oil is extracted from the treated well, at a first natural flow (since the injection of steam will have increased the reservoir pressure) and then by artificial elevation. The production decreases when the oil / vapor mixture cools, necessitating the repetition of the steam injection steps. The "Blow and Blow" method thus injects steam in periodic cycles, using periodic "snorting" of steam between Periodic soaking periods, during which the steam generating apparatus reaches and accumulates another volume of steam for subsequent injection. The process of "blowing and snorting" is very effective in the first steam cycles. However, typically it is only able to recover approximately 20% of the original oil in place (OOIP), compared to the steam flood, which has reported recovering more than 50% of the OOIP.

Steam flooding involves multiple wells. Some wells are used as steam injection wells, and others are used for oil production. Two mechanisms work to improve the amount of oil recovered. The first is to heat the oil to higher temperatures and therefore lower its viscosity so that it flows more easily through the formation to the production wells. A second mechanism is the physical displacement of oil in a manner similar to flooding with water, which means that oil is pushed into production wells. Although more steam is needed for this method than cyclic steam simulation methods, it is typically more effective to recover a greater proportion of the oil.

A form of flood with steam called "gravity drainage aided by steam", abbreviated "SAGD", uses multiple horizontal wells, separated. The steam is Injected into the upper SAGD well with effort to reduce the viscosity of the oil deposits to the point where gravity takes the oil to the production well.

However, it has become evident to us that, to maximize the recovery efficiency of crude oil, superheated steam can be injected concurrently with the extraction operation in a single well. In this way, delays are avoided, additional energy is available through the large number of degrees of overheating (defined as the difference between the actual temperature of the vapor and the saturation temperature at the injection pressure). In this way, the requirement for additional wells is ignored.

BRIEF DESCRIPTION OF THE INVENTION The present invention comprises methods and apparatus for injecting superheated steam, at low pressure, into the bottom of a well into a well concurrently with the extraction of crude oil from the production line. A high volume of superheated steam is injected continuously, concurrently with oil production. The superheated steam is preferably injected at temperatures that exceed 482.22 ° C (900 ° F) above the saturation temperature of the steam to the coincident pressure that is necessary to overcome the pressure losses by friction under the well plus a margin of 3.5155 KgF / cm2 (50 Psi) additional.

Preferably, the process allows the well pump to continue pumping while the superheated steam is injected into the well, heating the available oil reservoir and decreasing the viscosity. A separate steam pipe extends through a double-entry wellhead down the well. Preferably the steam line is attached to the production line of the well with belts configured generally in the form of an "8", and thus the steam injection pipe is parallel to the production line. The steam pipe is placed in the ring between the lining of the well and the production pipeline. This method of installation allows the oil well pump to continue operating while superheated steam is being injected to the bottom of the well.

Thus, a basic objective of this invention is to provide an improved, artificial well lift system.

Another objective is to provide a gas injection process at the bottom of an improved well that injects surface vapor at high exit temperatures.

A related objective is to provide a gas injection system for wells using steam overheated.

Likewise, an object of this invention is to provide a superheated steam gas injection system that is compatible with artificial lift pumping systems.

Also a basic objective is to provide steam injection means for practicing secondary oil recovery or improved tertiary oil recovery.

A related objective is to direct superheated steam into a well during the recovery of secondary or tertiary oil, so that the steam fills the voids left by the extracted oil and the vapor pressure contributes to the elevation to facilitate extraction.

A related objective is to provide an injection apparatus at the bottom of a well, of superheated steam, compatible with the existing well pipe to inject superheated steam.

A basic objective of our invention is to provide an injection system at the bottom of a well, reliable, to use superheated steam to recover crude oil.

Another objective of this invention is to provide methods and apparatus for injecting superheated steam at the bottom of a well at high volumes that are capable of high production or outlet temperatures of approximately 900 - 1500 degrees F (482.22 - 815.55 degrees C).

More particularly, it is an object of the invention to provide a bottomhole system to inject underground steam with a consistent heat capacity at 900 degrees F (482.22 degrees C) of superheat, ie, steam at a minimum temperature of 900 degrees F (482.22 degrees C) above the saturation temperature of a water-steam mixture, at a sufficient internal pressure to overcome the pro friction pressure losses associated with the roughness of the bottom surface of the pipeline, the mass flow velocity of the steam, and the geometrical parameters within the bottom of the well that exist from the upper side surface to the outlet of the steam pipe at the bottom of the well, concurrently with normal oil extraction processes running through of a separate production pipeline.

A related objective is to provide a downhole induction apparatus for superheated steam of the described character which concurrently injects steam during the oil extraction process through the normal production pipeline.

Another objective is to inject superheated steam into the bottom of a well concurrently with the extraction of oil through the well pipe.

Yet another object of our invention is to reduce the time delays associated with the "blow and snort" systems of the prior art.

It is also an objective to obviate the need for auxiliary wells that are typically required in the steam flooding techniques of the prior art.

Fundamentally, an important objective is to continuously heat deep crude oil deposits within wells during extraction, to decrease the viscosity of the oil, and thereby accelerate the recovery process.

These and other objects and advantages of the invention, together with the characteristics thereof, will appear or become apparent in the course of the following descriptive sections.

BRIEF DESCRIPTION OF THE FIGURES In the following figures, which form a part of the specification and which will be constructed in conjunction with it, and in which similar reference numbers have been used throughout to indicate similar parts in the different views: Figure 1 is a fragmented, descriptive and schematic view that shows an overview of our superheated steam distribution apparatus used with the preferred method; Figure 2 is a fragmented, descriptive and schematic view showing the installation of an induction or steam distribution pipe, the thermocouple at the bottom of the well, and the production pipe at a double-entry wellhead near a well of production; Figure 3 is an isometric view, partially fragmented, amplified, showing the installation and placement of jaws applied to the production pipeline and the steam pipeline near the double-entry wellhead before immersion into the well, with the proportions of them omitted for clarity; Figure 3A is a fragmentary, fragmented, sectional view, taken generally along the line 3A-3A in Figure 3 in the direction of the arrows, showing the preferred belt ties; Figure 4 is an isometric, fragmented, amplified view, similar to Figure 3, showing the upper portions of the double-entry wellhead, with portions omitted for clarity; Figure 5 is a view similar to Figure 4, with the jaws omitted, showing the appearance of the steam pipe, the production pipe and the thermocouple wiring at the top of the well head after the tubes have been submerged down into the well; Figure 6 is a schematic and sectional view, combined, showing the above-ground portions of the invention and the subterranean portions of the invention, including a section of penetrating straw, the tube at the bottom of the well, with portions thereof. shown in court for clarity or omitted for brevity; Figure 6A is similar to the view of Figure 6 but shows a pipe at the bottom of the well, in one piece, continuous; Figure 7 is a sectional view, fragmented, of the lower portions of the well where highly viscous tar sands appear, which should be compared with Figure 8 for an appreciation of the invention, and, Figure 8 is a sectional view, fragmented, amplified, derived from the circled region "8" in Figure 6.

DETAILED DESCRIPTION OF THE INVENTION As is well recognized by those skilled in the art, steam generated through a variety of techniques can be injected into wells through various pipe arrangements for the recovery of secondary and tertiary oil. With the initial reference now directed to Figures 1 and 2 of the appended Figures, a high volume of superheated steam is produced, preferably at the temperature between about 1000 degrees F and 1600 degrees F (537.77 degrees C and 871.11 degrees C), it is supplied by a steam generator, which has been designated generally by the reference number 10.

A suitable superheated steam generator is illustrated in our earlier US Patent No. 8,358,919 issued on January 22, 2013, entitled "Superheated Steam Generator with Accumulating Heating Tanks", the entire description of which is therefore incorporated as reference as if it were fully exposed here.

However, in the best mode known to us up to now, the results obtained with the present invention teachings on the bottom of a well are maximized by supplying steam through the techniques and apparatuses described in our currently co-pending applications: Patent Application No. 20130136435, published May 30, 2013 and entitled "Methods for Generating Superheated Steam," US Patent Application No. 20130136434 published May 30, 2013 and entitled "Automated Superheated Steam Generators," and Application US Patent No. 20130136433 published May 30, 2013 and entitled "Superheated Steam Generators". For habilitation and description purposes, the three published applications mentioned above are they therefore incorporate as a reference as if they were fully presented here.

The superheated steam generator 10 can be placed on the support surface 11, as the base of a platform truck trailer, near the well 14. The steam is distributed from the generator 10 through a steam outlet pipe, isolated, elongate 12 (Figure 1) communicating through an elbow 16 and a double inlet well head 17 with the steam pipe at the bottom of the well 18. Preferably the outlet pipe 12 should have as few folds as possible, and large-radius bends are preferred when two bends are required. A suitable two-inlet wellhead comprises a Model 92 double-string piping head available from Larkin Products in axahachie Texas.

Also entering the double inlet well mouth 17 (Figure 5) is a production line 20 which is partially coupled by a polished rod 22 (comprising part of a string of conventional suction rods) manipulated by the flange 24. A conventional rod pump 26 is placed near the well. As recognized by those skilled in the art, the rod pump 26 oscillates an upper rocker 28 which rotates the horse's head 29 up and down to create suction to extract oil through the production line 20 by oscillating a string of extraction rods, as is known in the art. With additional reference jointly directed to Figure 2, the installation on an open well proceeds with a conventional crane 34 which elevates the apparatus to the position with the proper wiring 32. Its lengths of production pipes 20 and steam distribution pipes are lowered. through the double-entry well mouth 17 with the help of a hydraulic drill pipe pliers 40. Preferably a thermocouple assembly for the bottom of the well including the thermocouple 43 is also lowered in place (Figure 8), which is recognized by those skilled in the art, is sized and configured to match the weight and load requirements. Suitable hydraulic drill pipe pliers include the ZQ series pliers available from Rugao Yaou Co. LTD., Room 907 13 #, Jinjiuhuafu, Ninghai RD, Rugao, Jiangsu, China.

With reference now directed to Figures 3 and 3A, the production line 20, and the steam distribution line 18 are preferably secured in parallel, spaced relative to a plurality of separate "Stauff" type clamps 46. Note in FIG. Figure 3, that the suitable tweezers are preferably SS type steel tweezers available from Stauff Im Ehrenfeld 458971, Werdohl, Germany. Alternatively, the steam distribution pipe hot 18 is attached to the production line 20 to heat it when there are heavy paraffin conditions. Due to the temperature range of up to 1600 degrees F (871.11 degrees C), it is critical that the bottom distribution pipe of steam 18 be made of a heat resistant material, such as stainless steel. In the best mode, inconel type 617 stainless steel is used.

With wells having large amounts of paraffin, the steam distribution or injection pipe 18 is not insulated to heat the production line. In a well with low paraffin, the steam distribution pipe is preferably isolated by efficiency.

When the viscosity of the extracted mixture decreases due to the effect of heat, the sand tends to be discarded due to the density difference. The connection of the steam pipe 18 to the production pipe 20 is achieved through the use of mechanical coupling guides and pipe 46 which are consistent with the different temperatures of the respective two pipes and construction materials of each respective pipe. The relative axial and circumferential displacements with the different temperatures and materials of construction of the two tubes are controlled within acceptable national consensus codes and standards through the appropriately selected connection and pipe coupling guides.

The thermocouples, (or other heat measuring devices) are connected to the production line 20 at each junction of the production line. An acceptable thermocouple is the East Coast Sensors type K thermocouple probe, which comprises a single element, ungrounded junction, which is insulated with magnesium oxide, which extends along the bottomhole steam pipeline. and made of 316 stainless steel. The thermocouple 43 (Figure 8) can be verified through wires 44 with an Extech digital thermocouple. This thermocouple 43 should be deviated from the production pipeline of one to two inches to measure ambient pressures within the environment.

Note Figures 3 and 4, that the production pipe 20, the steam pipe 18, and the thermocouple line at the bottom of the well 44 are laterally stabilized by the double-entry well mouth 17. After the isolation of the latter, a protective liner 54 is secured in place by means of a conventional upper lining nut 50 which is engaged by the ends 58 over the double inlet well mouth 17.

Turning now to Figures 6-8, the production pipe 20 and the steam pipe 18 extend down into the well jacket 60 through several layers of layers 62, 63. The production zone near the bottom of the well is designated in a general way by the number of reference 65 (Figure 6). The production zone 65 is typically approximately 21.33 m (70 ft) from the lower mouse trap 67, in which there is an accumulation of liquids, comprising water, oil and possibly extraction solvents, etc. The steam pipe is preferably connected to the production pipe 20.

Preferably the production line 20 will include a generally cylindrical, linear pump, which creates lift to force the crude oil to the top through the production line. When the original pressure that initially produces an eruptive well ceases, a secondary extraction process is necessary. There the lift is improved by the vacuum of the suction rod and the lift pump of the production line. The steam pipe 18 preferably ends generally at a mid-point relative to the production pipe, at least 3.04 m (10 feet) of pipeline elevation.

The thermocouple verified by line 44 is placed in a specific position relative to the end of the steam pipe. Preferably, the thermocouple is placed approximately 0.60 m (2 feet) below the steam pipe 18.

There is a specific method for mounting stages of the steam pipe relative to the production pipe 20.

The steam pipe joints should be approximately in the center of the production pipe to provide rigidity.

Figure 7 illustrates a prior art well that lacks steam injection. The inlet head of the production line 7 has a viscous, heavier extract 72 which obstructs its inlet orifices 74. The perforations 76 are also periodically blocked by heavy, viscous oil containing materials 78. It can be seen that the lack of a Local environment heated with steam contributes to the accumulation of waste and viscous mixtures, which limit the effectiveness and productive efficiency of the well. Paraffin problems can also be solved by vapor heating that makes the paraffin more viscous.

On the other hand, temperatures at the bottom of the steam-injected well (Figure 8) are estimated at 93.33-204.44 ° C (200-400 ° F). The vapor pressure at the bottom of the well where the steam exits the outlet of the steam pipe at the bottom of the well 19 (Figure 8) is preferably 2.81- 3.51 KgF / cm2 (40-50 psig) exceeding the pressure sufficient to overcome frictional pressure losses associated with the roughness of the surface of the pipe at the bottom of the well, the basic flow velocity of the steam, and the geometrical parameters within the pipe at the bottom from the well that exists from the surface on the upper side to the outlet of the steam pipe 19 at the bottom of the well. The orifices of the inlet mouth 74 are not blocked by deposits or viscous material. The sweep holes of the coating 76 are also not blocked. The accumulated oily extract, water and material 80 inside the mousetrap can be sucked upwards through the production pipe due to the heating effect of the steam.

From the foregoing, it will be noted that this invention is well adapted to obtain all the purposes and objectives set forth herein, together with other advantages that are inherent in the structure.

It will be understood that certain features and subcombinations are useful and can be used without references to other characteristics and subcombinations.

Since many possible embodiments of the invention can be made without departing from the scope thereof, it should be understood that all of the material set forth or shown herein in the accompanying Figures should be construed as illustrative and not in a limiting sense.

Claims

1. An injection apparatus at the bottom of a well to inject steam into wells equipped with at least one double-entry well head, production line that extends through the well head to the well, and a lift pump, The production line comprises at least one connection, the injection device is characterized in that it comprises: an elongated steam outlet pipe that distributes or injects steam from a steam generator to be used by the appliance; Steam pipe at the bottom of the well to conduct steam from the outlet pipe through the well head to the well at temperatures between 1000 and 1600 degrees F (537.77 and 871.11 degrees C), and at a pressure between 40 and 50 PSIG (2.81 KgF / cm2 and 3.51 KgF / cm2) on the friction losses and others found from the surface to the outlet of the steam pipe; where the steam pipe at the bottom of the well and the production pipeline are stabilized laterally by the mouth of the double entry well; heat measurement means in the bottom of the well placed inside the well to detect the temperature of the steam; Y means to mechanically secure the pipeline steam at the bottom of the well to the production pipe in a substantially parallel heat exchange relationship with it.

2. The downhole injection apparatus according to claim 1, characterized in that the steam is distributed to the well at a pressure of approximately 50 PSIG (3.51 KgF / cm2) on the friction or other losses found from the surface to the steam pipe outlet

3. The bottomhole injection apparatus according to claim 2, characterized in that the bottomhole steam pipe comprises heat-resistant inconel stainless steel.

4. The downhole injection apparatus according to claim 2, characterized in that the means for securing the steam distribution pipe at the bottom of the well to the production line comprise pipe guides that couple the steam distribution pipe. and the steam distribution pipe and accommodate the temperature difference.

5. The downhole injection apparatus according to claim 4, characterized in that the heat measuring means are connected to the production line.

6. The injection apparatus at the bottom of the well according to claim 5, characterized in that the heat measuring means comprise Type K thermocouples comprising a joint not connected to ground, of a single element.

7. The downhole injection apparatus according to claim 6, characterized in that the thermocouple is isolated magnesium oxide.

8. The downhole injection apparatus according to claim 7, characterized in that the thermocouple comprises Type 316 stainless steel.

9. The downhole injection apparatus according to claim 6, characterized in that the thermocouple is verified by a digital thermocouple connected through wires extending from the well.

10. The downhole injection apparatus according to claim 1, characterized in that the steam line at the bottom of the well generally ends at a mid point relative to the production line, above the lift pump.

11. The downhole injection apparatus according to claim 1, characterized in that the thermocouple is placed below the end of the steam distribution pipe.

12. A method for injecting steam into the bottom of a well in wells equipped with at least one wellhead double entry, extending the production pipe at the bottom of the well through the mouth of the well to the production area inside the well, and a lift pump, the method is characterized because it comprises the steps of: provide the steam generator near the well to produce a source of steam; distribute steam from the generator to the steam pipe at the bottom of the well that penetrates the well head and conducts steam to the well; measure the temperature of the steam inside the well below the steam pipe; securing the steam pipe at the bottom of the well to the production pipeline in a substantially parallel relationship with it; Y laterally stabilize the steam pipe at the bottom of the well and the production pipeline with a double-entry wellhead, and; driving steam through the wellhead into the well at temperatures between 1000 and 1600 ° F (537.77 and 871.11 degrees C) at pressures between 40 and 50 PSIG (2.81 KgF / cm2 and 3.51 KgF / cm2) on the friction losses and others found from the surface to the outlet of the steam pipe.

13. The method in accordance with the claim 12, characterized in that the steam is distributed at a pressure of approximately 50 PSIG (3.51 KgF / cm2) on the friction and other losses found from the surface of the steam pipe outlet.

14. The method according to claim 12, characterized in that the steam pipe at the bottom of the well comprises heat resistant inconel stainless steel.

15. The method according to claim 12, characterized in that the securing step comprises the step of mechanically coupling the steam pipe to the production line with pipe guides to accommodate the temperature difference of the steam distribution pipe and the pipeline of production.

16. The method according to claim 12, characterized in that the step of measuring the temperature of the steam employs type K thermocouple probes comprising a non-grounded connection of a single element.

17. The method according to claim 16, characterized in that it includes the step of isolating the thermocouple with magnesium oxide insulation.

18. The method in accordance with the claim 12, characterized in that the thermocouple comprises Type 316 stainless steel.

19. The method according to claim 12, characterized in that the thermocouple is verified by a digital thermocouple connected through wires that are They extend from the well.

20. The method according to claim 12, characterized in that the wells are high in paraffin, the steam distribution pipe is coupled to the production line in steam exchange relation.